Reservoir Engineering Notes

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PTRL6001

RESERVOIR ENGINEERING I

by

Val Pinczewski

School of Petroleum Engineering University of New South Wales

Sydney NSW 2052. AUSTRALIA

March, 2002

Prepared for

PETROLEUM ENGINEERING DISTANCE

LEARNING PROGRAM

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IMPORTANT NOTICE

2002 University of New South Wales. All rights are reserved.

This copy of the manual and accompanying software was prepared in accordance with copyright laws for the sole use of students enrolled in a course at the Uni-versity of New South Wales. It is illegal to reproduce any of this material or to use it for any other purpose.

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Chapter 1 INTRODUCTION

For those unfamiliar with reservoir engineering or reservoir geology the following section gives a brief summary of some basic concepts. If you are familiar with this material skip this section.

1.1 BASIC CONCEPTS

1.1.1 Accumulation of Sediments

The accumulation of sediments in a basin depends on the balance between the energy of the depositional environment (water velocity) and the sedimentation velocity of the particles. The sedimentation velocity depends on the size and density of the particles. Sediments carried by high velocity streams may be deposited in the delta region of the river where flow velocities are much slower. Smaller particle sediments may be further moved by waves and currents to other locations where the environmental energy is insuﬃcient to carry the particles further. This process leads to sorting of sediments with the accumulation of sand grains in one area and clay and silt particles in another area.

The depositional energy at a particular location varies with time. This results in a sequential deposition of sand (large particles) and shale (fine particles) producing sequences of sand and shale. (layering). This layering or vertical heterogeneity is the single most important characteristic determining reservoir performance and recovery.

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1.1.2 Origin of Petroleum

The precursors of petroleum, organic matter from dead plants and animals, are deposited together with fine-grained sediments in shallow marine environments during low energy periods of basin formation. Quite water is deficient in oxygen leading to the creation of anaerobic conditions and preservation of the organic matter. Anaerobic bacteria decomposes the organic matter to produce com-pounds of carbon, hydrogen (hydrocarbons) and oxygen. The conversion of the organic matter occurs over geological time as sediments become progressively buried and temperature and pressure increase.

The minimum temperature for oil and gas formation is about 150o_{F and the}

maximum is about 320o_{F. Since temperature increases with depth, this results in}

a burial depth window of between 7,000 ft to 23,000 ft for fine grained sediments containing organic matter (source rocks) to produce oil and gas.

Increasing burial causes the fine-grained sediments to undergo compaction and the source rocks eventually become eﬀectively impermeable. As the particles compact the generated hydrocarbon particles (oil or gas) are squeezed from the source rock. This process is called primary migration. The expelled hydrocar-bon particles, in the form of colloidal solutions (micelles) or individual drops or bubbles, enter the overlying and underlying water saturated permeable sand lay-ers which have retained their porosity and permeability because the coarse sand grains are stronger than the fine-grained silt and clay particles and therefore better withstand the increasing compaction forces with increasing burial depth.

1.1.3 Hydrocarbon Traps

The expelled hydrocarbon is lighter than the water in the interconnected pore space of the permeable sand layers and moves upwards as a result of buoyancy. This is called secondary migration. The upward migration of generated hydrocar-bon continues until it is halted by an impermeable barrier or trap. As hydrocarhydrocar-bon accumulates under the trap a reservoir is formed.

The characteristics of hydrocarbon traps are illustrated by considering a porous permeable formation between two impermeable layers which has been folded by tectonic action into an anticline (see the attached figure). This is called an an-ticlinal trap. The hydrocarbon contained in the reservoir may be oil or gas or both.

Here are some commonly used terms to describe petroleum reservoirs. You will probably be familiar with most of these terms.

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Figure 1.2: Cross-section for an anticlinal reservoir

Formation: the rocks, These may be either clastic rocks (sandstones) or lime-stone and dolomite (carbonates).

Spill point: the lowest point of the trap that can hold hydrocarbon. Trap closure: the distance between the crest and the spill point.

Reservoir: the part of the formation which contains hydrocarbon (oil and/or gas) and connate water.

Connate water: water in the pore space occupied by hydrocarbons. Gas cap: gas filled zone or gas reservoir.

Oil zone: oil reservoir.

Water zone or aquifer: the body of water bearing rock in hydraulic commu-nication with the reservoir.

Gas-oil contact: lowest depth at which gas can be produced. Oil-water contact: lowest depth at which oil can be produced. Bottom water: water below the oil-water contact.

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Figure 1.3: Anticline structural trap

Figure 1.4: Faulted structural trap

1.1.4 Classification of Traps

Hydrocarbon traps are classified as either structural or stratigraphic. Structural traps

Structural traps are formed by tectonic processes acting on sedimentary layers after deposition. They may be classified as,

Fold traps - formed by compressional or compactional anticlines.

Fault traps - formed by displacement of blocks of rock as a result of unequal tectonic forces.

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Figure 1.5: Salt dome structural trap Stratigraphic traps

Stratigraphic traps are produced by facies (rock type) changes in the formation such as pinchouts and lenticular sand bodies surrounded by impermeable shales. The processes involved in the formation of stratigraphic traps are complex because they involve changes in the depositional environment.

Stratigraphic traps may be associated with unconformities. An uncomformity forms when a site of sediments is uplifted, eroded and buried again under new layers of sediments that may form the trap. Unconformities generally separate formations formed under very diﬀerent depositional conditions.

Study the attached figures in the context of the above discussion. This will improve your understanding of the basic concepts. Note the following important points in the last of the figures:

(i) The oil and gas zones in the central block are not in direct pressure com-munication with the oil and gas zones in the left and right blocks. The oil and gas zones have diﬀerent contacts.

(ii) However, it cannot be concluded from the section alone that the central block is completely isolated from the rest of the formation. The blocks may be in pressure communication through the aquifer.

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Figure 1.6: Stratigraphic trap

Figure 1.7: Schematic of an oil and gas reservoir with a faulted central block and diﬀerent fluid contacts

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Figure 1.8: USA oil resource

1.2 OIL RECOVERY PROCESSES

Oil recovery operations are generally classified into three groups.

Primary Recovery - production using only natural reservoir energy (natural water drive, gas cap expansion, solution gas drive and pressure depletion drive).

Secondary Recovery - water or gas injection to maintain reservoir pressure (waterflooding and immiscible gas injection to supplement natural reservoir energy).

Tertiary Recovery - enhanced oil recovery processes (EOR).

An EOR process is any process which does a better job of recovering oil than conventional technology (primary and secondary recovery processes). In an EOR process conventional water or gas is replaced by a more eﬀective (more expensive) recovery agent.

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1.2.1 Residual Oil Resource (Target for EOR )

Conventional primary recovery methods are usually very ineﬃcient and, on the world average, recover approximately 1/3 of the OOIP.

- 2/3 OOIP cannot be produced by conventional recovery technology. - current EOR technology can produce about 20% —30% of the residual oil

resource.

1.2.2 Residual Oil is Trapped or By-passed

Oil which cannot be recovered using existing facilities or infrastructure (existing investment) is trapped (microscale) or by-passed (macroscale) - trapping of oil occurs on all reservoir length scales.

- Trapping on the micro or pore scale is by capillary forces.

- Trapping on the macro or field scale is caused by areal and vertical by-passing.

Trapping on all scales is strongly influenced by heterogeneity.

1.2.3 Recovery Processes

Unrecovered oil may be classified into two categories: Unrecovered mobile oil and immobile or residual oil.

- Unrecovered mobile oil can be recovered by conventional processes by im-proved access to the reservoir. Reservoir access may be imim-proved by,

- infill drilling.

- horizontal and multilateral wells.

- removal of formation damage caused by completion operations. - fracking.

- perforating unperforated layers.

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Figure 1.10: Recovery processes

- Immobile oil cannot be recovered by primary and secondary recovery processes such as waterflooding and immiscible gas injection. This oil can only be recovered by tertiary EOR processes.

All EOR techniques attempt to recover residual oil by: (i) Improving reservoir sweep eﬃciency .

(ii) Mobilizing immobile or residual oil.

1.2.4 Primary Recovery Mechanisms

An estimate of the likely primary production mechanism for a reservoir may be made on the basis of geological data even before the reservoir has been produced.

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For example:

(i) Thin, flat reservoirs with low permeability will most likely produce by a solution-gas drive mechanism.

(ii) Reservoirs having high closure and high permeability may experience the beneficial eﬀects of gravity segregation of oil and gas. This may supplement the eﬀectiveness of the original gas cap, or form a secondary gas cap. (iii) High permeability reservoirs in contact with an extensive aquifer will benefit

to some degree from natural water influx (water drive).

Material balance calculations may be used to determine the relative importance of the various natural drive mechanisms for a particular reservoir. Material balance calculations require:

(i) Accurate and comprehensive production history. (ii) Representative fluid samples for PVT analysis. (iii) Periodic pressure surveys.

The importance of instituting a program to gather this data as early as possible in the development and production life of a reservoir cannot be over emphasized. A good data gathering program is a key component of an eﬀective reservoir management strategy.

1.2.5 Secondary Recovery

Predictions of future reservoir performance are required, amongst other things, to identify the need and timing for secondary gas or water injection. Useful estimates of future production trends can be obtained from a knowledge of:

(i) The size of the gas cap relative to the size of the oil reservoir. (ii) The size of the aquifer relative to the size of the oil zone.

(iii) Formation permeability can be estimated from core data and flow tests on wells.

Drill-stem tests on dry holes and structurally low wells (wells penetrating the aquifer) may yield important indications of aquifer permeability and continuity. Sometimes it is useful to complete dry holes as aquifer observation wells. Pressure data from such wells can be important in characterizing reservoir-aquifer systems. The aquifer can have a profound eﬀect on reservoir performance.

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Figure 1.11: Steam flooding process

1.2.6 Tertiary Recovery — EOR Processes

The same techniques used to determine the need for secondary recovery are used to assess the need for tertiary developments. Decisions regarding the actual im-plementation of EOR processes are not made until suﬃcient field data is available to accurately assess primary and secondary performance.

EOR processes may be classified into three major categories: 1. Chemical

— Micellar Polymer Flooding — Polymer Flooding

— Caustic or Alkaline Flooding 2. Thermal

— Steam Flooding — Fire Flooding

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Figure 1.12: Carbon dioxide flooding process 3. Miscible

— Enriched Hydrocarbon Gas Flooding — CO2 Flooding

— Nitrogen and Flue Gas Flooding

The complexity of these processes requires the gathering of large quantities of ad-ditional laboratory fluid and core data and the use of considerably more complex analysis techniques.

1.3 WHAT IS RESERVOIR ENGINEERING?

Reservoir Engineering is the science of understanding the production characteristics of oil and gas fields under primary (natural pressure depletion), secondary (water flooding, immiscible gas flooding) and tertiary (EOR) drive mechanisms.

A basic understanding of reservoir engineering concepts is necessary for the plan-ning, development and production of oil and gas fields.

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Figure 1.13: Chemical flooding process

Geologists and Petrophysicists provide a description of the structure of the forma-tion or reservoir and vital physical parameters describing the reservoir internal structure and initial distribution of fluids. The reservoir engineer utilizes this data together with well production rates and measured reservoir pressures to analyze and interpret the data in order to optimize oil and gas recovery.

Reservoir Engineers are required to answer the following three vital questions: 1. How much hydrocarbon (oil and/or gas) does a reservoir initially

contain(initial hydrocarbon in-place)?

2. How much of the hydrocarbon initially in-place can ultimately be recovered?

3. How will the production rates of wells depend on the physical pa-rameters of the reservoir, reservoir geometry (shape), well num-ber and development pattern and how will the rate decline with time?

The first question may be answered if the shape and size of the pay zone is known and the distribution of porosity and water saturation in the zone are also known.

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This data is provided by the geologist and the petrophysicist. The reservoir engineer may assist by estimating the positions of gas-oil and water-oil contacts if the positions of these contacts is unknown.

The answer to the second question is very complex. It requires the use of sophisti-cated mathematical models (usually computer based reservoir simulators). These are required to model the many alternative developments which result in diﬀerent ultimate recoveries and profitability. The process of producing production fore-casts for the diﬀerent recovery mechanisms and development plans will always be associated with some degree of uncertainty because geologic formations are highly heterogeneous and the geological description, no matter how sophisticated, can never capture all the geologic variability.

The answer to the third question relies on detailed analysis of pressure and indi-vidual well test data.

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Chapter 2 RESERVOIR DESCRIPTION

The basis for a sound understanding of reservoir performance is a good description of reservoir geology (geological model) and the distribution of fluids (oil, water and gas) it contains. This is the first step in a reservoir engineering study.

Rock and Reservoir Description

Reservoir engineering studies require that the physical makeup of a reservoir be represented in a usable manner. This should include;

(i) a description of reservoir stratification (reservoir lithology), (ii) a description of reservoir geometry, both areally and vertically,

(iii) information on porosity, permeability, and water saturation throughout the reservoir, and

(iv) a description of the size and permeability of the adjoining aquifer.

This information is represented by various types of maps and cross-sections. These are usually prepared by production geologists.

Reservoir Heterogeneity

Most reservoirs are layered because of variations that existed in the depositional environment. Depositional conditions at any instant also vary from one location to another which results in lateral as well as vertical changes within the reservoir and within individual rock units. As we will see later, these changes result in

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variations in porosity, fluid distribution, and permeability. Permeability is a measure of the relative ease with which fluids flow through the rock.

Wireline logs

Electric and other types of logs can be very important tools for determining reservoir layering. Reservoir cross-sections based on logs can show if permeable zones are continuous throughout the reservoir or if they are lenses having limited areal extent.

Logs also show the net sand at each well. Net sand is the rock that contains recov-erable hydrocarbons and possesses permeability. A geologist should be consulted when analyzing logs for reservoir zonation and net sand thickness. Generally, logs are available for all wells drilled and represent the most complete set of reservoir descriptive data. Methods of analyzing logs and techniques of using logs for de-termining net sand thickness and evaluating sand continuity are beyond the scope of this course.

Core analysis

Core analysis data provide an additional basis for determining net sand thickness and reservoir zonation. Core analysis data is more quantitative than logs in describing the reservoir, but generally, only a fraction of the wells are cored. However, in most cases logs are more eﬀective when supported by core data. The logs can be calibrated by core data to make them more useful from a quantitative standpoint. Under some conditions, the calibrated logs can be used to obtain fairly good estimates of the porosity and permeability profiles at all wells in a reservoir.

Stratification

Stratification or heterogeneity occurs on all length scales in a reservoir. Although reservoir stratification is usually considered only in terms of net sand layers and impermeable streaks of sand or shale, stratification also exists within the net sand layers themselves and the degree of porosity and permeability can vary greatly within each strata.

Porosity and Permeability

The two most important properties of net sand are porosity and permeability. Porosity of net sand usually is in the range from 10 to 30 %. Some limestone and dolomite reservoirs locally may have porosities as high as 60 %. The porosity in reservoir rocks usually occurs in the spaces between rock particles and this is called primary porosity or intergranular porosity. Primary porosity can also exist in fractures and vugs. Primary porosity may be modified by post depositional events. For example, small mineral particles may be deposited in the space

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Figure 2.4: Schematic of wireline logging operation

tween sand grains to produce microporosity. These digenetic changes may greatly reduce the original porosity and permeability of a rock.

Typically, the permeabilities of the net sand portion of a reservoir will vary from 10 md or less to 500 md or more. The ability of a rock to allow fluid flow is proportional to permeability, so fluid flow profiles in the reservoir may be very uneven.

The process of reservoir description is sometimes referred to as formation evalu-ation and reservoir characterizevalu-ation. It involves the following steps:

(i) Gathering of data on the physical characteristics of formation rocks. (ii) Gathering of data on the characteristics, occurrences and distribution of

fluids within these rocks.

(iii) Interpretation of the above data for accuracy and reliability. These data are used to evaluate initial volumes of oil and gas in the reservoir

(iv) Evaluation of potential sources of reservoir production energy. e.g. extent of aquifer and size of gas cap.

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Figure 2.7: Diamond coring bits

Data collection is expensive (wireline logging, sampling, pressure testing etc.) and the collection of poor quality or inaccurate data is contradictory and wasteful. It is therefore necessary to place considerable eﬀort into preparing an eﬀective data gathering program.

2.1 RESERVOIR DESCRIPTION PROGRAM

The primary objectives of a data gathering program are to answer the following questions:

(i) Does the formation contain commercial quantities of oil and gas? (ii) How should the reservoir be produces to maximize economic return? or, more specifically,

(i) How much stock tank oil and/or free gas is initially in place?

(ii) What is the likely primary recovery mechanism and will it be necessary to supplement this energy by water or gas injection?

(iii) What are the oil and gas reserves (production volumes for a particular field development)?

(iv) How will individual well rates decline, and how can the decline in production rate be arrested?

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Figure 2.10: Length scales for laboratory core analysis

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The above questions cannot all be answered immediately after drilling of a discov-ery well. However, provided that the data gathering program is well thought-out, the engineer can arrive at reasonable planning estimates.

As the field is developed and produced, additional data becomes available, and this is integrated with the existing data to reduce the level of uncertainty associ-ated with the initial estimates.

The overall data gathering program is thus a continuing process over the life of the field. It is important to recognize this when developing the initial data gathering program.

2.2 SOURCES OF DATA

The following is a guide to the type of data which may be collected with the drilling of the first well in a reservoir:

- Original reservoir pressure and temperature. - Gross reservoir thickness at the well.

- Lithology of the reservoir rock.

- Stratigraphic sequence of rock at the well. - Reservoir porosity.

- Initial fluid saturations.

- Well productivity (permeability). - Characteristics of reservoir fluid. The above information is obtained from:

(i) Core samples. (ii) Wireline logs. (iii) Fluid samples.

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Additional delineation or development wells drilled after the first discovery well should provide the following data:

- Reservoir thickness variations to allow mapping of the field. - Areal variations in permeability, porosity and water saturation. - Continuity of stratigraphic units between wells.

- Vertical permeability variations (vertical barriers to flow) in the reservoir. - Variations of sub-sea depth of reservoir top and base for structure maps. - Depth Of gas-oil and oil-water contacts.

- Variations in fluid compositions within the reservoir.

These factors are determined in the same manner as for the first well. The presence of multiple wells allows interference testing between wells to determine average permeabilities between wells and to test the continuity of individual sand units.

Not all of the above data will be collected from each well drilled. The engineer must continually assess the data gathering process and only collect that data which materially reduces the level of uncertainty in estimating the important reservoir parameters.

When areal variations in rock properties are large, it may be necessary to collect all the data from all the wells drilled and to drill additional data wells.

2.2.1 Coring And Core Analysis

Coring is the most basic formation evaluation tool. It provides the engineer with the only opportunity to physically inspect a piece of the reservoir. It provides the only means of determining,

(i) Reservoir wettability. (ii) Capillary pressure. (iii) Relative permeability. (iv) Residual oil saturation.

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These are important in determining formation production characteristics and reservoir recovery factors.

Measurements on reservoir core samples are also required for:

(i) Calibration of wireline logs, essential for quantitative log interpretation. (ii) Identifying potential causes of formation damage.

It is diﬃcult to base an entire reservoir description entirely on core analysis data. This is because even in a heavily cored reservoir, the total cored volume constitutes only a very small fraction of the entire reservoir volume. As a result, it is very diﬃcult to assess the statistical significance of the data. At least one well in the reservoir should be cored over the entire producing interval. The data obtained provides valuable information for describing vertical variations in reservoir rock properties.

2.2.2 Wireline Logging

Wireline logging provides information on: (i) lithology,

(ii) porosity,

(iii) water saturation,

of the formation penetrated by a well. Whereas only a few wells are fully cored, it is common practice to log all wells in the field.

Logs provide the basis for determining, (i) gross and net formation thickness,

(ii) correlations identifying individual reservoir sand units, (iii) continuity of reservoir sand units,

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There are three basic types of log:

1. Electric — fundamental log run in all wells drilled. Most electric logs must be run in an uncased hole containing conducting fluid.

2. Sonic — Usually run in open hole.

3. Radioactivity — can be run successfully under nearly all wellbore conditions. Although logs provide valuable data for reservoir description, the main purpose of logging is to identify a suitable completion interval for the well.

A logging program should be designed to designed to provide the data required for reservoir description at a minimum cost. Lithology and borehole conditions must be considered in the selection of a suitable suite of logs. This will usually require a trial-and-error process of selecting the most eﬀective combination of logs for a particular reservoir. Prior experience is a major fracture in the design of an eﬀective logging program.

2.2.3 Pressure and Production Testing

Pressure and production tests are designed to determine, (i) fluid content,

(ii) formation productivity.

Production tests repeated on a yearly basis over the life of a well provide valuable information on,

(i) wellbore plugging,

(ii) reservoir pressure decline,

(iii) invasion of the wellbore by water or gas.

Pressure build-up and draw-down tests involve flowing a single well at a constant rate for a predetermined period of time and then shutting-in the well and observing the rate at which the wellbore pressure rises or falls with time. An analysis of the pressure response allows an estimate of formation productivity and permeability.

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Figure 2.12: Wireline formation interval tester

Interference tests provide checks on formation permeability and continuity. These tests involve flowing a production well and measuring the resulting pressure decline at nearby wells.

Drill-stem tests are usually run at the time the well is drilled to determine if the well should be completed over the interval identified by the well log. The DST tool allows us to make a temporary completion to conduct pressure build-up and draw-down tests. DST’s are useful for:

(i) testing the potential production intervals,

(ii) locating the positions of gas-oil and oil-water contacts, (iii) Determining average reservoir pressure.

2.2.4 Fluid Sampling

Reservoir oil usually contains a considerable amount of dissolved gas. When the oil is produced to the surface the gas comes out of solution and the oil volume consequently shrinks. The oil that fills a barrel at surface conditions will have occupied between 10%—50% at reservoir conditions.

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Figure 2.14: Single and multi-well pressure tests

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To determine oil-in-place it is necessary to know the number of stock tank barrels occupied by a reservoir barrel of oil.

Other important properties of oil, such as density and viscosity, also change when solution gas is released. These properties are very important in reservoir fluid flow calculations and must be accurately known.

In large reservoirs having high closure, fluid properties may vary significantly both areally and vertically. Enough samples should be taken to adequately describe these variations.

Reservoir fluid may be sampled in two ways:

1. Subsurface — wireline samplers in the wellbore at the perforations or as part of the initial open-hole formation evaluation program.

2. Recombined surface samples — oil and gas samples from the test sepa-rator recombined in the ratio of the produced gas-oil ratio.

2.3 INTEGRATED FORMATION

EVALUA-TION PROGRAM

No single wireline tool or procedure is capable of providing all the data required to characterize a reservoir and its contents. It is therefore necessary to develop an integrated formation evaluation program which consists of a carefully considered mix of:

(i) Logs - these provide most of the data for reservoir characterization. (ii) Cores - used to calibrate logs for quantitative interpretation.

(iii) Well testing - provide estimates of permeability and productivity. (iv) Fluid sampling - only means of determining reservoir fluid properties.

The best approach is to adopt a Key Well Program. The following steps are taken in the development of such a program:

1. A number of Key wells are selected to provide a representative coverage over the reservoir. A rule of thumb is that at least one well is needed for each 640 acres. For heterogeneous reservoirs this is reduced to 320 acres or less.

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Figure 2.17: Surface sampling for laboratory recombination

2. A data gathering program is designed for each key well. This will include logging, coring and well testing to provide complete reservoir coverage over the reservoir.

3. Determining which logs provide the best quantitative data by comparing log interpretations with core data. Logs run in non-key wells are then interpreted according to the correlations developed for the key wells. 4. Any available production data from key wells is also used to aide log

inter-pretation.

5. The above data gathering procedures are continuously monitored with the objective of eliminating any unnecessary or ineﬀective procedures.

The above steps ensure a data gathering procedure which is both simple and cost eﬀective.

A reservoir description program is needed during all phases of the producing life of a field.

1. Early in the development of the field this information is required to achieve proper well spacing and productive completions.

2. After field development the information is used for reservoir energy control in order to achieve high ultimate recovery.

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Figure 2.19: Aquifer models - limited data and interference

3. Secondary and Tertiary recovery. To eﬀectively engineer these processes it is necessary to have an accurate reservoir description and an estimate of hydrocarbon recovery.

In addition to production wells it may be necessary to drill observation wells. These wells can provide data which includes:

(i) Reservoir pressure.

(ii) Pressure gradients in the reservoir. (iii) Position and movement of contacts.

Contacts can be detected by production tests, cased hole logging and 4D high-resolution interwell seismic.

2.4 AQUIFER DESCRIPTION

The aquifer is the total volume of porous water-bearing rock in pressure commu-nication with a hydrocarbon reservoir. The size and permeability of an aquifer will control how much water drive energy is available to the reservoir. The aquifer

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energy will determine if the reservoir will produce primarily by water drive or by liquid or gas expansion within the reservoir. Reservoir drive mechanisms will be discussed in detail later in the course. At the present time, we are concerned only with methods of determining the size and permeability of an aquifer. If an aquifer is large, most of the information on it must come from wells drilled outside the reservoir area. Logs and drill-stem tests on dry holes are about the only source of aquifer data. Logs will show the thickness of water-bearing rock that is in communication with the reservoir. If enough dry holes are available, the areal extent of the aquifer can be estimated. An estimate of the aquifer permeability can be determined from the results of drill-stem tests on dry holes. Equations for calculating permeability from flow test data will be studies in the portion of the course entitled fluid flow.

The aquifer can have a major eﬀect on the production-pressure per-formance of a reservoir. This topic will be covered in detail in the section on water drive reservoirs.

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Chapter 3 VOLUMETRICS AND INITIAL

HYDROCARBON VOLUME

The first step in a reservoir study is to accurately determine the initial hydro-carbon volume. This requires data which will allow us to calculate the size and geometry of the reservoir and the fluid volumes which the reservoir contains. In this section we will briefly look at how maps and cross-sections are used to de-scribe the geometry of a reservoir and calculate the hydrocarbon volume in-place. Contour maps are commonly used to show reservoir geometry and the distribution of important reservoir parameters.

3.1 STRUCTURE MAPS

Structure maps show the geometric shape of a reservoir or formation. The maps may show the top or the bottom of a structure or reservoir unit. Examples of top of structure maps are attached. These maps also show the positions of fluid contacts in the reservoir.

Structure maps are prepared by geologists. The data on which the maps are drawn usually come from;

(i) well control,

(ii) geophysical data usually in the form of time maps, and

(iii) geological models of depositional and post-depositional events.

Gross thickness isopach maps show the total interval between the top and the base of the reservoir rock for each well. Structure maps on the top and on

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Figure 3.2: Top-of-structure map of a hydrocarbon reservoir

the base of the reservoir can provide data for the isopach map. Frequently, most of the wells are not drilled to the base of the reservoir so a base structure map cannot be drawn. In this case, the gross sand interval must be estimated from reservoir cross-sections based on logs from the well which penetrated the entire interval.

The gross pay isopach map for an oil reservoir is more descriptive of the hydro-carbon reservoir geometry than the gross thickness isopach.

3.2 ISOPACH MAPS

Isopach maps show the distribution and thickness of reservoir properties of in-terest. The contour lines connect points of equal vertical interval. Examples of common isopach maps are:

Gross oil thickness isopach map: contours gross pay - the depth of the top of the oil column minus the top of the bottom of the oil column.

Net oil thickness isopach map: contours net pay - gross pay minus non-reservoir intervals such as shales.

Net oil isopach maps are commonly used to calculate volumes of hydrocarbons in-place.

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Figure 3.3: Net sand isopach map for a hydrocarbon reservoir Other useful maps include:

Net-to-gross ratio maps: fraction of the total hydrocarbon interval which con-tributes to recovery.

Iso-porosity map: contours average porosity over net-pay portions of the de-sired formation.

Iso-water saturation map: contours average water saturation over net-pay portions of the desired formation.

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Figure 3.4: Isoporosity map for a hydrocarbon reservoir

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3.3 VOLUMETRIC METHOD FOR

DETER-MINING ORIGINAL OIL-IN-PLACE

The original oil-in-place (OOIP) contained in a reservoir expressed in Stock Tank Barrels (STB) is designated by the symbol N and is given by the equation (field units):

N = 7758Vbφ(1− Swi) Boi

where,

Vb = reservoir bulk volume (acre-feet)

φ = average porosity (fraction)

Swi = average initial water saturation (fraction)

Boi = average initial oil formation volume factor (RB/STB)

or, in any set of self consistent units:

N = Vbφ(1− Swi) Boi

In this and the following reservoir engineering courses it is assumed that you are familiar with units and unit conversions i.e., starting with the above equation for any set of self consistent units, you should be able to calculate the constant 7758 in the preceeding equation. If you wish to review the topic of units go to the section Units - unit conversions on page 108 of Dake, Fundamentals of reservoir engineering.

The original gas-in-place (OGIP) contained in a reservoir, expressed in Standard Cubic Feet (SCF), is designated by the symbol G and is given by the equation (in field units),

G = 7758Vbφ(1− Swi) Bgi

where,

Bgi = average initial gas formation volume factor (RB/SCF)

or, in any set of self consistent units:

G = Vbφ(1− Swi) Bgi

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Figure 3.6: Schematic of the microstructure of a sandstone showing sand grains and interconnected pore space which allows fluid flow

3.3.1 Reservoir Volume

The following information is required to calculate net reservoir volume: 1. Bulk reservoir Volume.

2. Reservoir Stratification (and net-to-gross ratio). The calculation procedure involves the following steps:

1. Prepare a map of gross reservoir thickness.

The map is based on log data and requires the construction of structure maps for;

(i) the top of the reservoir. (ii) the bottom of the reservoir.

The gross thickness is the diﬀerence in depth between the top and the bottom of the reservoir zone.

2. Construct a gross sand isopach map by removing intervals containing only gas or water. These intervals will generally lie above the gas-oil contact (GOC) and below the oil-water contact (OWC).

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3. Construct a net sand isopach map by eliminating all non-reservoir rock intervals (shale, siltstone, coal seam etc.).

This procedure will normally involve estimates of minimum porosity and permeability cut-oﬀs. The actual intervals to be excluded are picked from porosity logs which have been calibrated using core data.

The calculation is usually performed numerically using digitized maps.

3.3.2 Average Porosity

Average reservoir porosity is determined by mapping individual well porosity values. These are determined from core data and from sonic and radioactivity logs calibrated with core data.

3.3.3 Average Initial Water Saturation

The methods used to determine reservoir water saturation include: 1. Logging — induction and focused resistivity logs.

These logs measure formation resistivity which may be related to water sat-uration. This requires a knowledge of the wettability state of the reservoir and special core test data.

2. Coring with oil-based muds.

Provided that invasion of drilling fluids has not changed reservoir wettabil-ity, coring with oil-based mud can result in core which gives a good indi-cation of the irreducible water saturation. This corresponds to the water saturation in the reservoir above the transition zone.

In the transition zone the core will indicate low water saturation because the oil from the oil-based mud will have displaced some of the mobile water from the core during the coring operation.

3. Restored state tests.

These tests attempt to restore the wettability of core in the laboratory to that in the actual reservoir. The restored state core is then used in the laboratory to duplicate the displacement processes by which the reservoir water saturation was initially established.

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The data gathering program should include water saturation data determined by all of the above methods. Although cutting core with oil-based mud is expensive, at least one well should be cored in this manner to provide data for calibration of log resistivity.

Laboratory measurements on restored state core also provide capillary pressure data which can be used to calculate water saturations in the transition zone. This data is also used to calibrate logs. The overall objective is to collect suﬃcient data to develop meaningful correlations between log measured resistivity and water saturations in restored state laboratory tests.

3.3.4 Average Oil Formation Volume Factor

The average oil formation volume factor is required to convert the reservoir oil or gas filled hydrocarbon volume to the equivalent volumes at surface or stock tank conditions.

Oil and gas formation volume factors are determined in laboratory PVT tests conducted with representative samples of reservoir oil and gas.

Estimates of oil formation volume factors may be obtained from empirical corre-lations if the following are known:

(i) Initial gas-oil ratio (solution GOR). (ii) Reservoir temperature and pressure.

These are usually estimated from DST tests conducted on exploration wells.

3.3.5 Determining Initial Oil-In-Place

In order to illustrate the calculation of initial oil-in-place and introduce Mathcad - the spreadsheet program which we will be using throughout the course, we consider the very simple case of a homogeneous reservoir with unity net-to-gross ratio where the bottom of the reservoir is the horizontal surface formed by the water-oil contact (WOC). For these conditions a top-of-structure map and average porosity and water saturation are all that is needed to calculate the initial or original oil-in-place.

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Figure 3.7: Schematic of interstitual, irreducible or connate water in a waterwet porous medium

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Figure 3.8: Reservoir pressure survey map used to determine average reservoir pressure

Example 3.1 - Calculation of OOIP from a reservoir structure map [IHIP.mcd]

Calculate the initial volume of oil-in-place for the Apache Pool reservoir (top-of-structure map attached). The average porosity, average connate water saturation and average oil formation volume factor have been determined and these values are given below.

Data:

φ = 0.27 Swi = 0.38

Boi = 1.2715 (RB/STB)

We use this exercise to introduce you to Mathcad. It is assumed that you have installed Mathcad on your PC and that you have worked through the basics in the on-line tutorial. In order to see the solution to this exercise you will need to change some of the inputs to the spreadsheets. The areas of the spreadsheet where these changes may need to be made are highlighted in yellow.

[Answer: 340 MMSTB]

Solution outline

1. The first step is to determine the area inside each depth contour. The contour areas must be determined from the map. This is usually done

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using specialized computer software and digitized maps. For this example I have digitized each of the contours by hand and used Simpson’s rule to numerically calculate the area. The use of Simpson’s rule for numerical integration is shown in the attached figures. Study the three figures to be sure that you understand what is being done.

To determine the area of a depth contour I first printed an enlarged copy of the Apache structure map and overlayed this with a 1 cm by 1 cm grid. I then divided each contour into an upper and lower curve as shown in the attached figure and read-oﬀ the (x, y) points defining each curve. These points are entered into a file for each contour eg., [C2000.prn] in the folder [Contours]. If you open one of these files you will see the how the points are entered for the lower and upper contours. Note that the end-points for the lower and upper contours are the same. [Contour.mcd] , also located in the [Contours] folder, reads the contour files and calculates the areas, and plots the contour. This is done in the manner outlined in the course notes and you should have no trouble following the flow of the calculation. When Mathcad reads a file like [C2000.prn] all it ”sees” is a matrix of (x, y) numbers - it ignors blanks or anything which it does nor recognise as a numerical input. This makes it easy to annotate or ”pretty-up” the input file so that it is understandable to the casual reader.

You can use as many data points as you like to define a contour - the more points you use, the smoother the contour and the more accurate the area calculation. The only limitation is that the total number of points defining the lower and upper contours must be the same. This makes it a little easier to program the calculations.

When you open [Contour.mcd] you will see that I have left it doing one contour over and over. You will need to change the other input contour file names to see the areas and plots for each of the contours.

The areas within each contour, A0, A1, A2, etc. are multiplied by the map

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2. The bulk volume between two successive contours is given by the pyramidal formula: ∆Vi = h 3 µ Ai+ Ai+1+ q AiAi+1 ¶ where,

∆Vi = bulk volume between contours i and i + 1.

Ai = the area enclosed by the lower contour.

Ai+1 = the area enclosed by the upper contour.

h = the vertical height between the contours, or the contour interval.

3. The initial volume of oil-in-place in volume element ∆Vi,in any consistent

set of units (as used by Mathcad), is given by, ∆Ni =

∆Viφi(1− Swc,i)

Boi,i

4. The initial oil-in-place is the sum of the values for each volume element. N =X

i

∆Vi

See the attached figures which show how Simpson’s rule is used to calculate contour areas from digitized map data.

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1. Contour is divided into upper and lower curves

Upper curve

Lower curve

Figure 3.10: Computer calculation of contour areas

Simpson's rule to calculate the area under the upper and lower curves

A =Xyi − yi+ 1 2 ∆x yi yi+ 1 ∆x AU ∆x yi yi+ 1 AL

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Contour Area

A

U

A

L

A

C

= A

U

− A

L

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Problem 3.1 - Calculation of OGIP from a reservoir structure map How much gas would the Apache Pool contain if the initial reservoir pressure was 1500 psia, the initial reservoir temperature was 200o_{F, and the gas compressibility}

factor was 0.877 ? All other data as for Exercise 3.1. [Answer: 223 BSCF]

Solution hint

The gas formation volume factor is given by, Bg = 0.00504

zT

P [RB/SCF]

where T - the average reservoir temperature - is in o_{R (}o_R=o_{F +460) and P}

-the average reservoir pressure - is in psia. Use this equation to calculate -the gas formation factor.

You can use the areas, volumes etc., calculated in the previous exercise to help you solve this problem by hand calculation or using your favourite spread-sheet. If you do this be sure to be careful with units. If you want to master Mathcad you can modify the files used in the previous example to do the calculation. If you choose to do this make sure that you have looked at the Units section of the on-line Mathcad tutorial before making the necessary changes.

Problem 3.2 - Calculation of OGIP from a reservoir structure map Estimate the initial volume of gas-in-place for the Marlin Field (top-of-structure map attached). The average reservoir and fluid properties are given below. Data: φ = 0.21 Swi = 0.19 T = 210o_F P = 2300 psia z = 0.89 [Answer: 6.48 TSCF]

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Figure 3.13: Marlin field top-of-structure map Solution hint

You are free to solve this problem any way you want including using any com-mercial or in-house software to which you may have access. If you have been following the Mathcad route - I recommend this strongly - this problem will bring you right up the learning curve.

Print a full-size (or larger) copy of the Marlin structure map. Create a full copy of the folder for Example 3.1 and in order to modify the files to solbe the present problem.

Follow the outline for Example 3.1 and construct the data files for contours (there are 9 of these). Pay special attention to the particular manner in which these files are constructed! Modify the [Contour.mcd] by copy-and-paste to calculate the areas for all nine contours. Modify the final graph which plots the contours to plot all nine contours. You will probably need to revise the ’graphs’ section of the on-line manual to do this.

You will need to make the same changes to [Contour.mcd] made for Problem 3.1 to convert it to a gas in-place calculation. Note that for the Marlin contours the contour depth intervals are not all the same size. The best way to handle this is to read-in individual values of h in the same way as we already read-in individual values of porosity, initial water saturation, areas etc. You can do this

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by adding a column of numbers to the input data file and making the appropriate changes in the spreadsheet. These changes will involve reading-in the new values, introducing a new array for h, and modifying the equations to calculate with the array elements hi. Describing these changes is a lot more diﬃcult than making

them!

If you succede in making the above changes you will have learnt all you need to know to reproduce any of the Mathcad spreadsheets in this and other courses.

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3.4 DETERMINATION OF OIL-IN-PLACE —

MATERIAL BALANCE METHOD

Material balance methods are another way of determining the initial hydrocarbon content of a reservoir. Material balance calculations:

1. Require some production history (reservoir pressure and fluid production rates with time). The more production history available, the greater the accuracy of the calculation.

2. The method is most precise for reservoirs where water influx is not sig-nificant.

The method is most accurate for gas-cap-drive reservoirs if the pressure drop is at least 100 psi.

The material balance method is the preferred method for determining the original gas-in-place (OGIP) for gas reservoirs with no significant water influx.

For reservoirs where water influx is significant the analysis procedure is as follows:

1. OOIP is determined using the Volumetric Method.

2. The Material Balance Equation is used to calculate the water influx. 3. The computed water influx and measured reservoir pressures are used to

characterize the size and strength of the aquifer.

4. The Material Balance Equation is then used to predict future water influx and hence future reservoir performance.

For Material Balance calculations to produce realistic results it is necessary to: 1. Accurately determine initial reservoir pressure.

This should be measured as part of the data gathering program for the discovery well.

2. Initiate a program for periodic reservoir pressure measurement immediately after commencement of production. This program (on an annual basis) should be continued throughout the producing life of the field.

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3. Accurately measure and diligently report the production volumes for all the fluids produced. Although produced oil volumes are accu-rately measured as a matter of routine, material balance calculations require equally accurate water and gas volumes.

4. Accurately determine fluid PVT data. This requires representative oil and gas samples at reservoir conditions. The best oil samples are ob-tained before the reservoir is produced because the pressure drop which accompanies production may result in the release of solution gas and this may preclude the possibility of obtaining a representative fluid sample. Gas sampling does not have this problem.

3.5 ESTIMATING RESERVES

Reserves for a particular field are estimated from an analysis of the available engineering data. The implication of this is that the more reliable the data (production history data), the more accurate will be the estimate of reserves.

The procedure for estimating reserves involves the following steps: 1. Establish the primary production mechanism.

2. Apply the analysis procedure appropriate to the drive mechanism to es-timate reserves. This will usually involve the use of numerical reservoir simulators.

Rock property data (porosity and permeability), fluid property data, reser-voir description and production performance data (pressure decline and fluid production rates) are the basis for the analysis.

Collecting all production data from early in the life of a field is ,again, of critical importance.

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3.6 ESTIMATING DECLINE IN OIL

PRO-DUCTION RATES

The decline in field and individual well production rates is estimated on the basis of:

1. Decline curve analysis.

Decline curve extrapolation is satisfactory only for wells which are produced continuously at maximum or near maximum rates. For wells producing at limited draw-down (below their maximum rate) extrapolated decline rates are not meaningful.

Decline curve analysis are studied in detail in course PTRL6007 - Reservoir Engineering II.

2. Productivity index method.

The productivity index for a well is the well production rate per psi of pressure draw-down. This is determined from well flow tests.

The productivity index is usually a function of flow rate and reservoir pres-sure (oil relative permeability, oil viscosity). Well flow tests must therefore be conducted at diﬀerent rates and the productivity index must be adjusted for falling reservoir pressure.

For wells not subject to severe water and/or gas coning this method provides reliable estimates of production decline rates.

3. Reservoir simulation.

For wells subject to severe water and/or gas coning reservoir simulation oﬀers the most reliable method for predicting well decline rates and overall reservoir performance.

Reservoir engineering is studied in detail in course PTRL6004 - Reservoir Simulation.

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Chapter 4 HYDROSTATIC PRESSURE

DISTRIBUTION IN

RESERVOIRS

This section deals with the hydrostatic or initial pressure distribution in a reser-voir - the pressure which exists prior to significant production from the reserreser-voir. We will consider the following specific topics:

1. Introduction to hydrostatic pressures in reservoirs.

2. Determination of gas-oil and water-oil contacts from pressure data.

3. Determination of oil water and gas densities and gradients from pressure data.

4. Calculation of pressure kicks on penetrating a hydrocarbon zone.

5. Locating exploration wells searching for oil in a water- or gas-bearing for-mation.

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Symbols and Units

g gravity constant m/s2

D depth to subsurface m

p pressure N/m2

ρ density kg/m3

Dowc depth of initial oil-water contact m

Dgoc depth of initial gas-oil contact m

Dgwc depth of initial gas-water contact m

g = 9.81 m/s2

1 Pascal (Pa) = 1 N/m2 1 bar = 105 _N/m2

1 Atmosphere = 1.01325 bar or 14.695 psia Conversion factors lb/ft3 × 16.02 = kg/m3 psi _{× 6.9} = kPa psi _{× 0.069 = bar} ft _{× 3.28} = m

All of the above units may be embedded into working Mathcad files and can be used interchangeably or you can even mix units if you want. Normally we would not elect to mix units!

4.1 SUBSURFACE PRESSURES

4.1.1 Water zone pressures

In normally pressured sedimentary basins water contained in the pore space of a reservoir (connate water) is in pressure communication with the atmosphere through the oceans or outcrops. Since the pore spaces which comprise the eﬀective porosity of the reservoir are all interconnected, and the reservoir and associated aquifer are initially in static equilibrium, pressure varies only with depth.

The diﬀerence in hydrostatic pressure between any two depth points in a forma-tion containing water is,

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where, ρ_w is the average density of water over the interval (D2 − D1) and g is

the gravitational acceleration. ρw varies with depth (pressure) and salinity. Since

water is only slightly compressible, it is customary to neglect the overbar symbol and simply write,

p2− p1 = ρwg(D2− D1)

where it is understood that ρw is the average pressure over the interval of interest.

If we take p0 to be the pressure at the surface (atmospheric) where D1 = 0, the

equation may be written as,

pwD− p0 = ρwgD

or,

pwD = p0+ ρwgD

The term ρwg(D2− D1) is the hydrostatic pressure diﬀerence which has units of

pressure. If we divide this pressure diﬀerence by (D2− D1), we obtain the water

gradient, γw, which is equal to ρwg and has units of pressure per unit depth. In

general we define a phase pressure gradient as γi = ρig

where the subscript i may be o-oil, w-water or g-gas.

Using the definition of the fluid gradient, we can write that the pressure diﬀerence between any two depths, ∆pi, is

∆pi = γi∆D

where ∆D is the diﬀerence in depth.

For the water zone the pressure diﬀerence is ∆pw = γw∆D

The gradient for fresh water is 0.433 psi/ft.

4.1.2 Oil zone pressures

The initial pressure, poD, at depth D in the oil zone may be expressed in terms of

the oil pressure at the initial OWC (a commonly used datum point for reservoir engineering calculations) as,

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Figure 4.1: Hydrostatic pressure distribution in a reservoir which may be rearranged to give,

poD = po_{DOW C} − ρog(DOW C− D)

or,

poD = po_{DOW C} − γo(DOW C − D)

where ρo is the average density of oil at reservoir conditions.

4.1.3 Gas cap pressures

The initial pressure, pgD, at depth D in the gas cap may be expressed in terms

of the gas pressure at the initial GOC as,

pgD − pg_DGOC = ρgg(D− DGOC)

or,

pgD = pg_DGOC − ρgg(DGOC − D)

or,

pgD = pg_DGOC − γg(DGOC− D)

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4.2 HYDROSTATIC PRESSURE

DISTRIBU-TION IN A RESERVOIR CONTAINING

OIL, WATER AND GAS

In the absence of capillary pressure, the WOC and GOC are sharp and the fluid pressures at the contacts are equal. The resulting hydrostatic pressure distribu-tion in the reservoir is shown in the attached figure.

Note that the contacts correspond to the intersections of the fluid gradient lines. This can be used estimate the positions of the contacts from measured pressure-depth data.

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Figure 4.2: Hydrostatic pressure distribution in a reservoir assuming negligible capillary pressure

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Example 4.1 - Calculation of regional hydrostatic pressures [REGPRES.mcd]

Five widely separated exploration wells were drilled in a large sedimentary basin. While penetrating the aquifer, the following pressure measurements were made in each of the wells:

Well A B C D E

Rotary table elevation (ft above MSL) 2133 1312 2707 3937 197 Measured depth (ft) 9744 13993 8235 17388 9383 Gauge Pressure (psia) 4340 5656 2480 6005 4090 Determine if all the wells belong to the same pressure system.

In answering this question you can use the Mathcad spreadsheet [REGPRES.mcd] which reads the above data and calculates the required fluid gradients.

[Answer: Well-A is clearly in an overpressured separate hydraulic system]

Solution hints

The relationship between true vertical depth sub-sea DT V D, measured depth

DM D, and depth above mean sea level DM SL is given by

DT V D = DM D− DM SL

The average water gradient (sea-level to depth of measurement), γw, is given by

γw =

∆p DT V D

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Example 4.2 - Calculation of fluid contacts and fluid gradients from pressure data [CONTACTS.mcd]

The following formation tester pressure measurements were made in an explo-ration well. Estimate:

(i) the depths of the contacts

(ii) the density and the nature of the fluids present in the formation Depth Pressure (ft) (psia) 8120 2912 8202 2920 8284 2927 8366 2950 8448 2978 8530 3005 8612 3038 8694 3075 8776 3114 Solution hints

Plot the data on a depth-pressure plot. Identify lines of constant slope, these show zones of diﬀerent fluid saturation. Determine the gradients of depth-pressure lines and from these calculate the fluid densities. The densities identify the fluids. [CONTACTS.mcd] is a general spreadsheet which I have found very useful in analysing a wide range of formation pressure-depth data. If you have access to commercial or in-house software which does similar things, feel free to use it. [Answer: DGOC= 8302 ft ss., DOW C= 8573 ft ss., ρg= 13.2 lb/cubic ft., ρo= 48.3

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Problem 4.1 - Optimal Location of an Exploration Well [EXPLOR.mcd] Exploration well EX-1 intersected a hydrocarbon bearing sand with a vertical thickness of 200 ft between 6560 and 6760 ft-subsea. A wireline formation tester recovered some gas and mud and recorded a pressure of 3850 psia at 6660 ft-ss. A second exploration well EX-2 encountered the same sand between 7780 ft-ss and 7980 ft-ss but found it to be only water-bearing. Mechanical problems with the downhole gauge prevented a pressure measurement from being taken. The two wells are 12,000 ft apart.

On the basis of previous experience and sampling of reservoir fluids we have deter-mined that the regional water gradient is 0.524 psi/ft. The formation is normally pressured. The pressure gradient for the gas phase at reservoir conditions is cal-culated to be 0.084 psi/ft. The oil gradient, at reservoir conditions, is estimated to be 0.296 psi/ft.

Questions

(i) Is the above data consistent with the assumption that the formation could be oil-bearing between 6660 and 7880 ft-ss ?

(ii) Where would you locate an additional exploration well which would defi-nitely find oil if any oil is indeed present?

(iii) What is the maximum possible thickness of the oil zone?

[Answers: (i) yes, (ii) new well should intersect the sand at a depth of 7445 ft ss., (iii) 910 ft.]

Solution hints

Each of the wells gives us a fluid and a corresponding fluid pressure. Where a mechanical problem prevented the measurement of a water phase pressure, we can estimate the pressure by assuming that the formation is normally pressured (i.e., water gradient times depth).

The first well gives us the depth of lowest known gas. The second well gives the depth of highest known water. If an oil zone exists, it must be between these depths.

Knowing the gas and water gradients, and a fluid pressure and corresponding depth in the gas and water zones, we can draw the gas and water gradient lines

Reservoir Engineering Notes

PTRL6001

RESERVOIR ENGINEERING I

PETROLEUM ENGINEERING DISTANCE

LEARNING PROGRAM

Contents

Chapter 1

INTRODUCTION

1.1

BASIC CONCEPTS

1.1.1

Accumulation of Sediments

1.1.2

Origin of Petroleum

1.1.3

Hydrocarbon Traps

1.1.4

Classification of Traps

1.2

OIL RECOVERY PROCESSES

1.2.1

Residual Oil Resource (Target for EOR )

1.2.2

Residual Oil is Trapped or By-passed

1.2.3

Recovery Processes

1.2.4

Primary Recovery Mechanisms

1.2.5

Secondary Recovery

1.2.6

Tertiary Recovery — EOR Processes

1.3

WHAT IS RESERVOIR ENGINEERING?

Chapter 2

RESERVOIR DESCRIPTION

Rock and Reservoir Description

Reservoir Heterogeneity

2.1

RESERVOIR DESCRIPTION PROGRAM

2.2

SOURCES OF DATA

2.2.1

Coring And Core Analysis

2.2.2

Wireline Logging

2.2.3

Pressure and Production Testing

2.2.4

Fluid Sampling

2.3

INTEGRATED FORMATION

EVALUA-TION PROGRAM

2.4

AQUIFER DESCRIPTION

Chapter 3

VOLUMETRICS AND INITIAL

HYDROCARBON VOLUME

3.1

STRUCTURE MAPS

3.2

ISOPACH MAPS

3.3

VOLUMETRIC METHOD FOR

DETER-MINING ORIGINAL OIL-IN-PLACE

3.3.1

Reservoir Volume

3.3.2

Average Porosity

3.3.3

Average Initial Water Saturation

3.3.4

Average Oil Formation Volume Factor

3.3.5

Determining Initial Oil-In-Place

Contour Area

A

A

A

= A